Over the last thirty years, the search for oil and gas offshore has moved into progressively deeper waters. Wells are now commonly drilled at depths of several hundreds, to even several thousands, of feet below the surface of the ocean. In addition, wells are now being drilled in more remote offshore locations.
In cold water production environments, such as found in these remote offshore locations, the management of hydrates in subsea equipment is important. Those of ordinary skill in the art will understand that hydrates may form within subsea wellheads, production equipment, risers, and elsewhere, in which hydrates restrict the flow of production fluids. Hydrates are crystals formed by water in contact with natural gases and associated liquids, which typically occurs in a ratio of 85 mole % water to 15% hydrocarbons. Hydrates can form when hydrocarbons and water are present at the right temperature and pressure, such as in wells, flow lines, or valves. The hydrocarbons become encaged in ice-like solids that do not flow, but which rapidly grow and agglomerate to sizes that can block production fluid passages and flow lines. Hydrate formation most typically occurs in subsea production equipment that is at relatively low temperatures and elevated pressures.
To manage this hydrate formation, operators may insulate the subsea production equipment, an expensive, difficult, and time-consuming process. For example, a production tree, normally installed subsea to control production fluids from oil and gas reservoirs, has a complex shape that makes it difficult to apply insulation. Further, some areas of the production tree are not available for insulation at all, as these areas of the production tree must remain accessible for manual re-entry and/or connection to the production tree and wellhead.
In addition, the operator may inject chemical “inhibitors” at or near the subsea wellhead, such as into the manifold. Gas hydrates may be thermodynamically suppressed by adding materials such as salts or glycols, which operate as “antifreeze.” Commonly, methanol or methyl ethylene glycol (MEG) may be injected at the subsea tree as the antifreeze material. Inhibitors are oftentimes introduced during well startup. The inhibitor will continue to be injected until the subsea equipment is sufficiently warmed by the produced fluids such that the risk of hydrate formation is abated.
The management of hydrates becomes more difficult when production is shut-in, whether planned or unplanned. For instance, the production of a well or a well-site may be shutdown, such as the result of an emergency at the well-site, host facilities platform, or vessel. An operator may not have time to inject an inhibitor so as to “inhibit” produced fluids resident in a production passage or line, and the lack of having any production fluids flowing through equipment may allow the equipment to cool down. This may result in the production equipment experiencing even cooler temperatures during a shut-in. As such, hydrate formation remains a priority to increase the efficiency of subsea production equipment.